1. Field of the Disclosure
The present subject matter is generally directed to drilling operations, and in particular, to systems and methods that may be used for cooling drilling mud.
2. Description of the Related Art
During a typical well drilling operation, such as when drilling an oil and gas well into the earth, a drilling mud circulation and recovery system is generally used to circulate drilling fluid, i.e., drilling mud, into and out of a wellbore. The drilling mud provides many functions and serves many useful purposes during the drilling operation, such as, for example, removing drill cuttings from the well, controlling formation pressures and wellbore stability during drilling, sealing permeable formations, transmitting hydraulic energy to the drilling tools and bit, and cooling, lubricating, and supporting the drill bit and drill assembly during the drilling operations.
Drilling muds commonly include many different types of desirable solid particles that aid in performing one or more of the functions and purposes outlined above. These solids particles used in drilling muds may have one or more particular properties which makes their presence in a particular drilling mud mixture desirable and beneficial. For example, some solids particles may need to be of a certain size or size range, which may be useful in sealing off more highly permeable formations so as to prevent the loss of valuable drilling fluid into the formation—so-called “lost circulation materials.” Other solids particles may need to be of a certain density so as to control and balance forces within the wellbore, which may be added as necessary to the drilling mud as required to guard against wellbore collapse or a well blowout during the drilling operation. High density particulate materials such as barium sulfate, or barite, (BaSO4), are often used for this purpose, as their greater unit volumetric weight serves to counterbalance high formation pressures and/or the mechanical forces caused by formations that would otherwise begin sloughing. In still other cases, solids particles may be added to the drilling mud based on a combination of the particle size and density, such as when a specific combination of the two properties may be desirable. Furthermore, the drilling mud in general, and the added solid particles in particular, can be very expensive. As such it is almost universally the case that upon circulation out of the wellbore, the desirable—and valuable—solids particles are generally recovered and re-used during the ongoing drilling cycle.
Once the drilling mud has served its initial purposes downhole, the mud is then circulated back up and out of the well so that it can carry the drill cuttings that are removed from the advancing wellbore during the drilling operation up to the surface. As may be appreciated, the drill cuttings, which are also solids particles, are thoroughly mixed together with the desirable solids particles that, together with various types of fluids, make up the drilling mud, and therefore must be separated from the desirable solids particles, such as barite and the like. In the best possible drilling scenario, it is advantageous for the drill cuttings to be substantially larger than the desirable solids particles making up the drilling mud, thus enabling most of the drill cuttings to be removed using vibratory separator devices that separate particles based upon size, such as shale shakers and the like. However, in most applications, a portion of the drill cuttings returning with the drilling mud are similar in size, or even smaller than, at least some of the desirable solids particles contained in the drilling mud, in which case secondary separation devices, such as hydrocyclone and/or centrifuge apparatuses, are often employed so as to obtain further particle separation.
There are a variety of reasons why it is desirable, and even necessary, to remove as many of the drill cuttings particles from the drilling mud mixture as possible. A first reason would be so as to control and/or maintain the drilling mud chemistry and composition within a desirable range as consistently as possible. For example, the presence of drill cuttings particles in the drilling mud mixture may have a significant effect on the weight of the mud, which could potentially lead to wellbore collapse, and/or a blowout scenario associated with possibly hazardous overpressure conditions within the well. More specifically, because the specific gravity of the drill cuttings particles are often significantly lower than that of the desired solids particles in the drilling mud, e.g., barite, the presence of cuttings particles left in the mud by the typical solids removal processes can cause the weight of the drilling mud to be lower than required in order to guard against the above-noted hazardous drilling conditions.
Additionally, the presence of undesirable solids materials in the drilling mud can also have an adverse effect on the flow and/or hydraulic characteristics of the mud, which, potentially, could detrimentally influence the operational efficiency of the hydraulically driven downhole tools, lubrication and cooling of the drill bit, and the like. Furthermore, depending on the types of materials (e.g., rocks/minerals) that make up the drill cuttings, the drill cuttings particles can be highly abrasive, and therefore could be damaging to the drilling mud circulation equipment, such as mud circulation pumps, seals, valves, and the like. In such cases, expensive drilling downtime may be encountered during the repair and/or replacement of inordinately worn or damaged equipment.
FIG. 1 schematically depicts one exemplary prior art system 100 that is sometimes used to circulate and treat drilling mud during a typical drilling operation. As shown in FIG. 1, a blow-out preventer (BOP) 103 is positioned on a wellhead 102 as drilling operations are being performed on a wellbore 101. In operation, drilling mud 110 mixed with drill cuttings 107 is circulated out of the wellbore 101 and exits the BOP 103 through the bell nipple 104, and thereafter flows through the flow line 105 to the drill cuttings separation equipment 106. As noted above, depending on the particle sizes of the returning drill cuttings 107 and the degree of particle separation required, the drill cuttings separation equipment 106 may include first stage separating equipment, such as one or more vibratory separators (e.g., shale shakers), as well as second stage separating equipment, such as one or more hydrocyclone and/or centrifuge apparatuses. However, for simplicity of illustration and discussion, the drill cuttings separation equipment 106 has been schematically depicted in FIG. 1 as a shale shaker device, and therefore will hereafter be referred to as the shale shaker 106.
After entering the shale shaker 106, the undesirable drill cuttings 107 are separated from the drilling mud 110 and directed to a waste disposal tank or pit 108. The separated drilling mud 110 then flows from the sump 109 of the shale shaker 106 to a mud pit or mud tank 111. Typically, the mud pit or mud tank 111 is a large container having an open top so that the drilling mud 110 can be exposed to the environment. In this way, at least some of the heat that is absorbed by the drilling mud during the drilling operation (e.g., from the surrounding formation and/or from the generation of drill cuttings) can be released to the environment, thus allowing the drilling mud 110 to naturally cool, as indicated by heat flow lines 113.
As shown in FIG. 1, the treated (e.g., cooled and/or separated) drilling mud 110 flows from the mud tank 111 to a mud pump 116 through the suction line 115. In some applications, a mud booster pump 114 may be used to deliver the drilling mud 110 through the suction line 115 and to the suction side of the mud pump 116. In operation, the mud pump 116 increases the pressure of the drilling mud 110 and discharges the pressurized drilling mud 110 to a standpipe 117, after which the mud 110 flows through a rotary line 118 to swivel 119 mounted at the upper end of a kelly 120. The kelly 120 then directs the treated drilling mud 110 down to the drill pipe/drill string 121, and the mud 110 is recirculated down the drill string 121 to a drill bit (not shown), where it once again provides, among other things, the cooling, lubrication, and drill cutting removal tasks previously described.
In some drilling applications, further enhanced drilling mud cooling is required beyond that which the system 100 of FIG. 1 is capable of providing. One such application is geothermal drilling. In general, geothermal wells are used to capture geothermal energy, which in turn can be used for heating and/or power generation applications. Therefore, many geothermal wells are, by design, drilled into formations that have significantly higher operating temperatures than most oil and gas wells. For example, in some geothermal drilling applications, the temperature of the targeted formations may be on the order of approximately 500-600° F. or even greater, a situation that can often lead to conditions wherein the temperature of the returned drilling mud/drill cuttings mixture is above 200-225° F. Such elevated mud temperatures can often have a significant detrimental effect on many of the various components of a typical mud handling system, including the mud circulation pumps, the associated seals and valves, and the like. Accordingly, a more active mud cooling system than what is depicted by the system 100 in FIG. 1 above is sometimes necessary in order to provide a greater degree of drilling mud temperature reduction, as will be further described in conjunction with FIG. 2 below.
FIG. 2 schematically depicts an illustrative prior art drilling mud circulation and treatment system 200 that is sometimes used in operations wherein higher drilling mud temperatures are generated during drilling operations, such as during geothermal drilling applications and the like. In general, several elements of the system 200 of FIG. 2 are substantially similar to corresponding elements of the previously described system 100 of FIG. 1 above. Accordingly, and where appropriate, the reference numbers used in describing the various elements of the system 200 shown in FIG. 2 substantially correspond to the reference numbers used in describing related elements of the system 100 illustrated in FIG. 1, except that the leading numeral in each figure has been changed from a “1” to a “2.” For example, the mud pump “116” shown in FIG. 1 corresponds to a mud pump “216” of FIG. 2, the BOP “103” of FIG. 1 corresponds to a BOP “203” of FIG. 2, the shale shaker “106” of FIG. 1 corresponds to a shale shaker “206” of FIG. 2, and so on. Accordingly, the reference number designations used to identify some elements of the system 200 may be illustrated in FIG. 2 but may not be specifically and/or fully described below. In those instances, it should be understood that the numbered elements shown in FIG. 2 which may not be fully described below substantially correspond to their like-numbered counterparts illustrated and described in conjunction with FIG. 1 above.
As shown in FIG. 2, a hot drilling materials mixture—which, as noted above, may be at a temperature in the range of 200-225° F.—flows from the bell nipple 204 on the BOP 203 to the shale shaker 206 through the flow line 205. Once in the shale shaker 206, the hot drilling materials mixture separated as described above with respect to the system 100 such that the separated drill cuttings 207 are sent to the waste disposal pit 208 and the separated hot drilling mud 210h flows down to the sump 209. Thereafter, the hot drilling mud 210h flows from the sump 209 to the hot mud tank 211h, wherein some amount of natural or passive mud cooling 213 may occur due to exposure to the surrounding environment.
Due to the higher drilling mud temperatures encountered during a typical geothermal drilling application, the hot drilling mud 210h must very often be further cooled beyond the otherwise incremental cooling 213 that occurs while the mud 210h is in the hot mud tank 211h. Accordingly, rather than pumping the hot drilling mud 210h directly from the hot mud tank 211h to the mud pump 216, the hot mud 210h is further cooled in a mud cooling tower 230. In the illustrative configuration shown in FIG. 2, a hot mud pump 231 is used to pump the hot drilling mud 210h exiting the hot mud tank 211h into the mud cooling tower 230 where it flows through a mud coil 232. As the hot mud 210h passes through the mud coil 232, it is cooled by a flow of air created by an induced draft fan 233 located at the top of the cooling tower 230.
After passing through the mud coil 232, the cooled drilling mud 210c exits the mud cooling tower 230 and flows to a cooled mud tank 211c, as shown in FIG. 2. Thereafter, a mud booster pump 214 draws the cooled drilling mud 210c from the cooled mud tank 211c and pumps the cooled mud 210c through the suction line 215 to the mud pump 216, where it is pump again pumped into the wellbore 210 through the drill pipe 221, as described above.
The system 200 can also be configured in such a way so that it can be operated in a cooling tower bypass mode. For example, as shown in FIG. 2, appropriate valving can be positioned within the system 200 and operated in such a way as to isolate the mud cooling tower 230 from the flow of hot drilling mud 210h from the hot mud tank 211 and to allow the hot mud 210h to flow directly from the hot tank 211 to the cooled mud tank 210c, e.g., through a cooling tower bypass line 230b. Such an operational configuration can be used when maintenance is required on the mud cooling tower 230 or during drilling operations wherein the temperature of the hot drilling materials mixture exiting the wellbore 201 does not require any additional cooling beyond the passive capabilities of the hot mud tank 211h. 
In spite of the additional mud cooling capability that is provided by the mud cooling tower 230, at least some of the equipment of the system 200 remains directly exposed to the hot drilling mud 210h, and thus to drilling mud temperatures in excess of 200-225° F. In particular, this includes all equipment and valving upstream of the cooling tower 230, such as the shale shaker 206, the hot mud pump 231, and the like. Generally, this is because at least the largest of the drill cuttings 207 must be usually be separated from the hot drilling mud 210h in the shale shaker 206 before the mud 210h reaches the pump 231. Accordingly, all of the mechanical equipment in the system 200 that is located upstream of the mud cooling tower 230 can be detrimentally affected by the higher drilling mud temperatures that are otherwise inherent in geothermal drilling operations. Furthermore, prolonged exposure to such higher operating temperatures can increase the likelihood of premature equipment failures and associated costly rig downtime, and therefore often lead to more frequent and costly inspection and/or maintenance activities.
The present disclosure is directed to drilling mud systems and methods of operating the same that may be used to mitigate, or possibly even eliminate, at least some of the problems associated with the prior art drilling mud systems described above.